Power Monitoring Systems and Methods

ABSTRACT

The present disclosure is a system for monitoring power that has a unified polyphase distribution transformer monitoring (PDTM) device that interfaces with at least three electrical conductors electrically connected to a transformer. In addition, the PDTM device measures a current and a voltage of each of the three electrical conductors. Additionally, the system has logic that calculates values indicative of power corresponding to the transformer based upon the currents and the voltages measured and transmit data indicative of the calculated values.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims priority to U.S. Provisional Application Ser.No. 61/803,086 entitled “Power Monitoring Systems and Methods,” filedMar. 18, 2013, and U.S. Provisional Application Ser. No. 61/806,513entitled “Power Monitoring System and Method,” filed Mar. 29, 2013, bothof which are incorporated herein by reference in its entirety.

BACKGROUND

Power is generated, transmitted, and distributed to a plurality ofendpoints, such as for example, customer or consumer premises(hereinafter referred to as “consumer premises”). Consumer premises mayinclude multiple-family residences (e.g., apartment buildings,retirement homes), single-family residences, office buildings, eventcomplexes (e.g., coliseums or multi-purpose indoor arenas, hotels,sports complexes), shopping complexes, or any other type of building orarea to which power is delivered.

The power delivered to the consumer premises is typically generated at apower station. A power station is any type of facility that generatespower by converting mechanical power of a generator into electricalpower. Energy to operate the generator may be derived from a number ofdifferent types of energy sources, including fossil fuels (e.g., coal,oil, natural gas), nuclear, solar, wind, wave, or hydroelectric.Further, the power station typically generates alternating current (AC)power.

The AC power generated at the power station is typically increased (thevoltage is “stepped up”) and transmitted via transmission linestypically to one or more transmission substations. The transmissionsubstations are interconnected with a plurality of distributionsubstations to which the transmission substations transmit the AC power.The distribution substations typically decrease the voltage of the ACpower received (the voltage is “stepped down”) and transmit the reducedvoltage AC power to distribution transformers that are electricallyconnected to a plurality of consumer premises. Thus, the reduced voltageAC power is delivered to a plurality of consumer premises. Such a web ornetwork of interconnected power components, transmission lines, anddistribution lines is often times referred to as a power grid.

Throughout the power grid, measurable power is generated, transmitted,and distributed. In this regard, at particular midpoints or endpointsthroughout the grid, measurements of power received and/or distributedmay indicate information related to the power grid. For example, ifpower distributed at the endpoints on the grid is considerably less thanthe power received at, for example, distribution transformers, thenthere may be a system issue that is impeding delivery of power or powermay be being diverted through malice. Such power data collection at anyof the described points in the power grid and analysis of such data mayfurther aid power suppliers in generating, transmitting, anddistributing power to consumer premises.

SUMMARY

The present disclosure is a system for monitoring power that has apolyphase distribution transformer monitoring (PDTM) device thatinterfaces with at least three electrical conductors electricallyconnected to a transformer. The PDTM device further measures a currentand a voltage of each of the three electrical conductors. The systemfurther has logic that calculates values indicative of powercorresponding to the transformer based upon the current and the voltagemeasured and transmit data indicative of the calculated values.

BRIEF DESCRIPTION OF THE DRAWINGS

The present disclosure can be better understood with reference to thefollowing drawings. The elements of the drawings are not necessarily toscale relative to each other, emphasis instead being placed upon clearlyillustrating the principles of the disclosure. Furthermore, likereference numerals designate corresponding parts throughout the severalviews.

FIG. 1 is a diagram depicting an exemplary power transmission anddistribution system in accordance with an embodiment of the presentdisclosure.

FIG. 2A is a diagram depicting a transformer and meter power usage datacollection system in accordance with an embodiment of the presentdisclosure.

FIG. 2B is a diagram depicting a line power usage data collection systemin accordance with an embodiment of the present disclosure.

FIG. 3 is a drawing of a general purpose transformer monitoring device,such as is depicted by FIG. 2A.

FIG. 4 is a block diagram depicting an exemplary operations computingdevice, such as is depicted in FIG. 2A.

FIG. 5 is a block diagram depicting an exemplary transformer monitoringdevice, such as is depicted in FIG. 2A.

FIG. 6 is a drawing of a transformer can in accordance with anembodiment of the present disclosure.

FIG. 7 is a drawing showing a satellite unit of the transformermonitoring device depicted in FIG. 3 being installed on the transformercan depicted in FIG. 6.

FIG. 8 is a drawing showing the satellite unit of the transformermonitoring device depicted in FIG. 3 installed on the transformer candepicted in FIG. 6.

FIG. 9 is a drawing showing a main unit of the transformer monitoringdevice depicted in FIG. 3 installed on the transformer can depicted inFIG. 6.

FIG. 10 is a drawing showing a main unit of the transformer monitoringdevice depicted in FIG. 8 installed on the transformer can depicted inFIG. 6.

FIG. 11 is a diagram depicting a method of monitoring power inaccordance with the system such as is depicted in FIG. 1 for a wyetransformer configuration.

FIG. 12 is a diagram depicting a method of monitoring power inaccordance with the system such as is depicted in FIG. 1 for a Deltatransformer configuration.

FIG. 13 is a diagram depicting a method of monitoring power inaccordance with the system such as is depicted in FIG. 1 for an OpenDelta transformer configuration.

FIG. 14 is depicts a polyphase distribution transformer monitoring(PDTM) device in accordance with an embodiment of the presentdisclosure.

FIG. 15 is block diagram depicting an exemplary PDTM device, such as isdepicted in FIG. 14.

FIG. 16 is a diagram depicting a method of monitoring power with a PDTMof FIG. 14 in accordance with the system such as is depicted in FIG. 1for a wye transformer configuration.

FIG. 17 is a diagram depicting a method of monitoring power with a PDTMof FIG. 14 in accordance with the system such as is depicted in FIG. 1for a Delta transformer configuration.

FIG. 18 is a diagram depicting a method of monitoring power with a PDTMof FIG. 14 in accordance with the system such as is depicted in FIG. 1for a Delta transformer configuration having a center-tapped leg.

FIG. 19 is a flowchart depicting exemplary architecture andfunctionality of the power transmission and distribution system such asis depicted in FIG. 1.

FIG. 20 is a flowchart depicting exemplary architecture andfunctionality of monitoring the power transmission and distributionsystem such as is depicted in FIG. 1 with a PDTM of FIG. 14.

DETAILED DESCRIPTION

FIG. 1 is a block diagram illustrating a power transmission anddistribution system 100 for delivering electrical power to one or moreconsumer premises 106-111. The one or more consumer premises 106-111 maybe business consumer premises, residential consumer premises, or anyother type of consumer premise. A consumer premise is any structure orarea to which power is delivered.

The power transmission and distribution system 100 comprises at leastone transmission network 118, at least one distribution network 119, andthe consumer premises 106-111 (described hereinabove) interconnected viaa plurality of power lines 101 a-101 j.

In this regard, the power transmission and distribution system 100 is anelectric “grid” for delivering electricity generated by a power station10 to the one or more consumer premises 106-111 via the transmissionnetwork 118 and the distribution network 119.

Note that the power lines 101 a and 101 b are exemplary transmissionlines, while power lines 101 c, 101 d, are exemplary distribution lines.In one embodiment, the transmission lines 101 a and 101 b transmitelectricity at high voltage (110 kV or above) and often via overheadpower lines. At distribution transformers, the AC power is transmittedover the distribution lines at lower voltage (e.g., 25 kV or less). Notethat in such an embodiment, the power transmission described usesthree-phase alternating current (AC). However, other types of powerand/or power transmission may be used in other embodiments.

The transmission network 118 comprises one or more transmissionsubstation 102 (only one is shown for simplicity). The power station 10is electrically coupled to the transmission substation 102 via the powerlines 101 a, and the transmission substation 102 is electricallyconnected to the distribution network 119 via the power lines 101 b. Asdescribed hereinabove, the power station 10 (transformers not shownlocated at the power station 10) increases the voltage of the powergenerated prior to transmission over the transmission lines 101 a to thetransmission substation 102. Note that three wires are shown making upthe power lines 101 a indicating that the power transmitted to thetransmission substation 102 is three-phase AC power. However, othertypes of power may be transmitted in other embodiments.

In this regard, at the power station 10, electricity is generated, andthe voltage level of the generated electricity is “stepped up,” i.e.,the voltage of the generated power is increased to high voltage (e.g.,110 kV or greater), to decrease the amount of losses that may occurduring transmission of the generated electricity through thetransmission network 118.

Note that the transmission network 118 depicted in FIG. 1 comprises onlytwo sets of transmission lines 101 a and 101 b (three lines each forthree-phase power transmissions as indicated hereinabove) and onetransmission substation 102. The configuration of FIG. 1 is merely anexemplary configuration. The transmission network 118 may compriseadditional transmission substations interconnected via a plurality ofadditional transmission lines. The configuration of the transmissionnetwork 118 may depend upon the distance that the voltage-increasedelectricity may need to travel to reach the desired distribution network119.

The distribution network 119 transmits electricity from the transmissionnetwork 118 to the consumer premises 106-111. In this regard, thedistribution network 119 comprises a distribution substation transformer103 and one or more distribution transformers 104 and 121. Note that theconfiguration shown in FIG. 1 comprising the distribution substationtransformer 103 and two distribution transformers 104 and 121 andshowing the distribution substation transformer 103 physically separatedfrom the two distribution transformers 104 and 121 is an exemplaryconfiguration. Other configurations are possible in other embodiments.

As an example, the distribution substation transformer 103 and thedistribution transformer 104 may be housed or combined together in otherconfigurations of the distribution network 119 (as well as distributionsubstation transformer 103 and distribution transformer 121). Inaddition, one or more transformers may be used to condition theelectricity, i.e., transform the voltage of the electricity, to anacceptable voltage level for delivery to the consumer premises 106-111.The distribution substation transformer 103 and the distributiontransformer 104 may “step down,” i.e., decrease the voltage of theelectricity received from the transmission network 118, before thedistribution substation transformer 103 and the distributiontransformers 104, 121 transmit the electricity to its intendeddestinations, e.g., the consumer premises 106-111.

As described hereinabove, in operation the power station 10 iselectrically coupled to the transmission substation 102 via the powerlines 101 a. The power station 10 generates electricity and transmitsthe generated electricity via the power lines 101 a to the transmissionsubstation 102. Prior to transmission, the power station 10 increasesthe voltage of the electricity so that it may be transmitted overgreater distances efficiently without loss that affects the quality ofthe electricity delivered. As further indicated hereinabove, the voltageof the electricity may need to be increased in order to minimize energylosses as the electricity is being transmitted on the power lines 101 b.The transmission substation 102 forwards the electricity to thedistribution substation transformer 103 of the distribution network 119.

When the electricity is received, the distribution substationtransformer 103 decreases the voltage of the electricity to a range thatis useable by the distribution transformers 104, 121. Likewise, thedistribution transformers 104, 121 may further decrease the voltage ofthe electricity received to a range that is useable by the respectiveelectrical systems (not shown) of the consumer premises 106-111.

In one embodiment of the present disclosure, the distributiontransformers 104, 121 are electrically coupled to a distributiontransformer data collection system 105. The distribution transformerdata collection system 105 of the present disclosure comprises one ormore electrical devices (the number of devices may be determined basedupon the number of transformers being monitored) (not shown) thatmeasure operational data via one or more electrical interfaces with thedistribution transformers 104, 121. Exemplary operational data includesdata related to electricity that is being delivered to or transmittedfrom the distribution transformers 104, 121, e.g., power measurements,energy measurements, voltage measurements, current measurements, etc. Inaddition, the distribution transformer data collection system 105 maycollect operational data related to the environment in which thedistribution transformers 104, 121 are situated, e.g., operatingtemperature of the distribution transformers 104, 121.

In accordance with one embodiment of the present disclosure, thedistribution transformer data collection system 105 electricallyinterfaces with power lines 101 e-101 j (e.g., a set of three powerlines delivering power to consumer premises 106-111, if the power isthree-phase). Thus, the distribution transformer data collection system105 collects the data, which represents the amount of electricity (i.e.,power being used) that is being delivered to the consumer premises106-111. In another embodiment, the distribution transformer datacollection system 105 may electrically interface with the power lines101 c-101 d (i.e., the power lines delivering receiving power from thetransmission network 118).

Furthermore, each consumer premise 106-111 comprises an electricalsystem (not shown) for delivering electricity received from thedistribution transformers 104, 121 to one or more electrical ports (notshown) of the consumer premise 106-111. Note that the electrical portsmay be internal or external ports.

The electrical system of each consumer premise 106-111 interfaces with acorresponding consumer premise's electrical meter 112-117, respectively.Each electrical meter 112-117 measures the amount of electricityconsumed by the consumer premises' electrical system to which it iscoupled. In order to charge a customer who is responsible for theconsumer premise, a power company (e.g., a utility company or a meteringcompany) retrieves data indicative of the measurements made by theelectrical meters 112-117 and uses such measurements to determine theconsumer's invoice dollar amount representative of how much electricityhas been consumed at the consumer premise 106-111. Notably, readingstaken from the meters 112-117 reflect the actual amount of powerconsumed by the respective consumer premise electrical system. Thus, inone embodiment of the present disclosure, the meters 112-117 store dataindicative of the power consumed by the consumers.

During operation, the meters 112-117 may be queried using any number ofmethods in order to retrieve and store data indicative of the amount ofpower being consumed by the meter's respective consumer premiseelectrical system. In this regard, utility personnel may physically goto the consumer premises 106-111 and read the consumer premise'srespective meter 112-117. In such a scenario, the personnel may enterdata indicative of the readings into an electronic system, e.g., ahand-held device, a personal computer (PC), or a laptop computer.Periodically, the data entered may be transmitted to an analysisrepository. Additionally, meter data retrieval may be electronic andautomated. For example, the meters 112-117 may be communicativelycoupled to a network (not shown), e.g., a wireless network, andperiodically the meters 112-117 may automatically transmit data to arepository, described herein with reference to FIG. 2A.

As will be described further herein, meter data (not shown) (i.e., dataindicative of readings taken by the meters 112-117) and transformer data(not shown) (i.e., data indicative of readings taken by the transformermonitoring data collection system 105) may be stored, compared, andanalyzed in order to determine whether particular events have occurred,for example, whether electricity theft is occurring or has occurredbetween the distribution transformers 104, 121 and the consumer premises106-111 or to determine whether power usage trends indicate a need ornecessity for additional power supply equipment. In this regard, withrespect to the theft analysis, if the amount of electricity beingreceived at the distribution transformers 104, 121 is much greater thanthe cumulative (or aggregate) total of the electricity that is beingdelivered to the consumer premises 106-117, then there is a possibilitythat an offender may be stealing electricity from the utility providingthe power.

In another embodiment, power usage data is compiled over time. Thecompilation of the power usage data may be used in a number of differentways. For example, it may be predetermined that a particular power usagesignature, e.g., power usage which can be illustrated as a graphedfootprint over a period of time, indicates nefarious activity. Such isdescribed further herein.

In one embodiment, the power transmission and distribution system 100further comprises a line data collection system (LDCS) 290. The LDCS 290collects line data from the transmission lines 101 b-101 d. The linedata is data indicative of power/electricity measured. Such data may becompared, for example, to meter data (collected at consumer premises106-111 described further herein) and/or the transformer data (collectedat the distribution transformers 104, 121 described further herein) inorder to determine losses of electricity along the power grid,electricity usage, power need, or power consumption metrics of the powergrid. In one embodiment, data collected may be used to determine whetherelectricity theft is occurring or has occurred between a transmissionsubstation and a distribution substation or a distribution substationand a distribution transformer (i.e., the distribution transformer thattransmits power to the consumer premise). Note that the LDCS 290 iscoupled to the transmission lines 101 b, 101 c, and 101 d, respectively,thus coupling to medium voltage (MV) power lines. The LDCS 290 measuresand collects operational data, as described hereinabove. In oneembodiment, the LDCS may transmit operational data, such as, forexample, power, energy, voltage, and/or current, related to the MV powerlines 101 b, 101 c, and 101 d.

FIG. 2A depicts the transformer data collection system 105 in accordancewith an embodiment of the present disclosure and a plurality of meterdata collection devices 986-991. The transformer data collection system105 comprises one or more transformer monitoring devices 243, 244 (FIG.1). Note that only two transformer monitoring devices 243, 244 are shownin FIG. 2A but additional transformer monitoring devices may be used inother embodiments, one or a plurality transformer monitoring devices foreach distribution transformer 104, 121 (FIG. 1) being monitored, whichis described in more detail herein.

Notably, in one embodiment of the present disclosure, the transformermonitoring devices 243, 244 are coupled to secondary side of thedistribution transformers, 104, 121 respectively. Thus, measurementstaken by the transformer monitoring devices 243, 244 are taken, ineffect, at the distribution transformers 104, 121 between thedistribution transformers 243, 244 and the consumer premises 106-111(FIG. 1).

Additionally, the transformer monitoring devices 243, 244, the meterdata collection devices 986-991, and an operations computing device 287may communicate via a network 280. The network 280 may be any type ofnetwork over which devices may transmit data, including, but not limitedto, a wireless network, a wide area network, a large area network, orany type of network known in the art or future-developed.

In another embodiment, the meter data 935-940 and the transformer data240, 241, may be transmitted via a direct connection to the operationscomputing device 287 or manually transferred to the operations computingdevice 287. As an example, the meter data collection devices 986-991 maybe directly connected to the operations computing device 287 via adirection connection, such as for example a T-carrier 1 (T1) line. Also,the meter data 935-940 may be collected on by a portable electronicdevice (not shown) that is then connected to the operations computingdevice 287 for transfer of the meter data collected to the operationscomputing device 287. In addition, meter data 935-940 may be collectedmanually through visual inspection by utility personnel and provided tothe operations computing device 287 in a particular format, e.g., commaseparated values (CSV).

Note that in other embodiments of the present disclosure, the meter datacollection devices 986-991 may be the meters 112-117 (FIG. 1)themselves, and the meters 112-117 may be equipped with networkcommunication equipment (not shown) and logic (not shown) configured toretrieve readings, store readings, and transmit readings taken by themeters 112-117 to the operations computing device 287.

The transformer monitoring devices 243, 244 are electrically coupled tothe distribution transformers 104, 121, respectively. In one embodiment,the devices 243, 244 are electrically coupled to the distributiontransformers 104, 121, respectively, on a secondary side of thedistribution transformers 104, 121.

The transformer monitoring devices 243, 244 each comprise one or moresensors (not shown) that interface with one or more power lines (notshown) connecting the distribution transformers 104, 121 to the consumerpremises 106-111 (FIG. 1). Thus, the one or more sensors of thetransformer monitoring devices 243, 244 senses electricalcharacteristics, e.g., voltage and/or current, present in the powerlines as power is delivered to the consumer premises 106-111 through thepower lines 101 e-101 f. Periodically, the transformer monitoringdevices 243, 244 sense such electrical characteristics, translate thesensed characteristics into transformer data 240, 241 indicative ofelectrical characteristics, such as, for example power, and transmittransformer data 240, 241 to the operations computing device 287 via thenetwork 280. Upon receipt, the operations computing device 287 storesthe transformer data 240, 241 received.

Note that there is a transformer monitoring device depicted for eachdistribution transformer in the exemplary system, i.e., transformermonitoring device 243 for monitoring transformer 104 (FIG. 1) andtransformer monitoring device 244 for monitoring transformer 121 (FIG.1). There may be additional transformer monitoring devices formonitoring additional transformers in other embodiments.

The meter data collection devices 986-991 are communicatively coupled tothe network 280. During operation, each meter data collection device986-991 senses electrical characteristics of the electricity, e.g.,voltage and/or current, that is transmitted by the distributiontransformers 104, 121. Each meter data collection device 986-991translates the sensed characteristics into meter data 935-940,respectively. The meter data 935-940 is data indicative of electricalcharacteristics, such as, for example power consumed in addition tospecific voltage and/or current measurements. Further, each meter datacollection device 986-991 transmits the meter data 935-940,respectively, to the operations computing device 287 via the network280. Upon receipt, the operations computing device 287 stores the meterdata 935-940 received from the meter data collection devices 986-991indexed (or keyed) with a unique identifier corresponding to the meterdata collection device 986-991 that transmits the meter data 935-940.

In one embodiment, each meter data collection device 986-991 maycomprise Automatic Meter Reading (AMR) technology, i.e., logic (notshown) and/or hardware, or Automatic Metering Infrastructure (AMI)technology, e.g., logic (not shown) and/or hardware for collecting andtransmitting data to a central repository, (or more centralrepositories), e.g., the operations computing device 287.

In such an embodiment, the AMR technology and/or AMI technology of eachdevice 986-991 collects data indicative of electricity consumption byits respective consumer premise power system and various otherdiagnostics information. The meter logic of each meter data collectiondevice 986-991 transmits the data to the operations computing device 287via the network 280, as described hereinabove. Note that the AMRtechnology implementation may include hardware such as, for example,handheld devices, mobile devices and network devices based on telephonyplatforms (wired and wireless), radio frequency (RF), or power linecommunications (PLC).

Upon receipt, the operations computing device 287 compares aggregatemeter data of those meters corresponding to a single transformer withthe transformer data 240, 241 received from the transformer thatprovided the transformer data 240, 241.

Thus, assume that meter data collection devices 986-988 are coupled tometers 112-114 (FIG. 1) and transmit meter data 935-937, respectively,and distribution transformer 104 is coupled to transformer monitoringdevice 243. In such a scenario, the meters 112-114 meter electricityprovided by the distribution transformer 104 and consumed by theelectrical system of the respective consumer premise 106-108. Therefore,the operations computing device 287 aggregates (e.g., sums) datacontained in meter data 935-937 (e.g., power usage recorded by eachmeter 112-114) and compares the aggregate with the transformer data 240provided by transformer monitoring device 243.

If the operations computing device 287 determines that the quantity ofpower that is being delivered to the consumer premises 106-108 connectedto the distribution transformer 104 is substantially less than thequantity of power that is being transmitted to the distributiontransformer 104, the operations computing device 287 may determine thatpower (or electricity) theft is occurring between the distributiontransformer 104 and the consumer premises 106-108 to which thedistribution transformer 104, is connected.

In one embodiment, the operations computing device 287 may store dataindicating theft of electricity. In another embodiment, the operationscomputing device 287 may be monitored by a user (not shown), and theoperations computing device 287 may initiate a visual or audible warningthat power (or electricity) theft is occurring. This process isdescribed further herein.

In one embodiment, the operations computing device 287 identifies,stores, and analyzes meter data 935-940 based on a particular uniqueidentifier associated with the meter 112-117 to which the meter datacollection devices 986-991 are coupled. Further, the operationscomputing device 287 identifies, stores, and analyzes transformer data240, 241 based on a unique identifier associated with the distributiontransformers 104, 121 that transmitted the transformer data 240, 241 tothe operations computing device 287.

Thus, in one embodiment, prior to transmitting data to the operationscomputing device 287, both the meter data collection devices 986-991 andthe transformer monitoring devices 243, 244 are populated internallywith a unique identifier (i.e., a unique identifier identifying themeter data collection device 986-991 and a unique identifier identifyingthe transformer monitoring device 243, 244). Further, each meter datacollection device 986-991 may be populated with the unique identifier ofthe transformer 104, 121 to which the meter data collection device986-991 is connected.

In such an embodiment, when the meter data collection device 986-991transmits the meter data 935-940 to the operations computing device 287,the operations computing device 287 can determine which distributiontransformer 104 or 121 services the particular consumer premises106-111. As an example, during setup of a portion of the grid (i.e.,power transmission and distribution system 100) that comprises thedistribution transformers 104, 121 and the meters 112-117, theoperations computing device 287 may receive set up data from thedistribution transformers 104, 121 and the meter data collection devices986-991 identifying the device from which it was sent and a uniqueidentifier identifying the component to which the meter data collectiondevice 986-990 is connected.

FIG. 2B depicts the line data collection system 290 in accordance withan embodiment of the present disclosure. The line data collection system290 comprises a plurality of line monitoring devices 270-272 and theoperations computing device 287. Each line monitoring device 270-272communicates with the operations computing device 287 via the network280.

With reference to FIG. 1, the line monitoring devices 270-272 areelectrically coupled to the transmission lines 101 b, 101 c, and 101 d,respectively. In one embodiment, each line monitoring device 270-272comprises one or more sensors (not shown) that interface with thetransmission lines 101 b, 101 c, and 101 d connecting the transmissionsubstation 102 downstream to the distribution substation transformer 103or connecting the distribution substation transformer 103 downstream tothe distribution transformers 104, 121.

The one or more sensors of the line monitoring devices 270-272 senseelectrical characteristics, e.g., voltage and/or current, present ascurrent flows through transmission lines 101 b, 101 c, and 101 d,respectively. Periodically, each line monitoring device 270-272 sensessuch electrical characteristics, translates the sensed characteristicsinto line data 273-275, respectively, indicative of suchcharacteristics, and transmits the line data 273-275 to the operationscomputing device 287 via the network 280. Upon receipt, the operationscomputing device 287 stores the line data 273-275 received from the linemonitoring devices 270-272.

FIG. 3 depicts an embodiment of a general purpose transformer monitoringdevice 1000 that may be used as the transformer monitoring devices 243,244 depicted in FIG. 2A and/or line monitoring devices 270-272 (FIG.2B). The transformer monitoring device 1000 may be installed onconductor cables (not shown) and used to collect data indicative ofvoltage and/or current from the conductor cables to which it is coupled.

The general purpose transformer monitoring device 1000 comprises asatellite unit 1021 that is electrically coupled to a main unit 1001 viaa cable 1011. The general purpose transformer monitoring device 1000 maybe used in a number of different methods in order to collect voltageand/or current data (i.e., transformer data 240, 241 (FIG. 2A) from thedistribution transformers 104, 121 (FIG. 1) and from the power lines 101b-101 j.

In order to collect voltage and/or current data, the satellite unit 1021and/or the main unit 1001 is installed around a conductor cable orconnectors of conductor cables (also known as a “bushing”).

In this regard, the satellite unit 1021 of the general purposetransformer monitoring device 1000 comprises two sections 1088 and 1089that are hingedly coupled at hinge 1040. When installed and in a closedposition (as shown in FIG. 3), the sections 1088 and 1089 connecttogether via a latch 1006 and the conductor cable runs through anopening 1019 formed by coupling the sections 1088 and 1089.

The satellite unit 1021 further comprises a sensing unit housing 1005that houses a current detection device (not shown) for sensing currentflowing through the conductor cable around which the sections 1088 and1089 are installed. In one embodiment, the current detection devicecomprises an implementation of one or more coreless current sensor asdescribed in U.S. Pat. No. 7,940,039, which is incorporated herein byreference.

The main unit 1001 comprises sections 1016 and 1017 that are hingedlycoupled at hinge 1015. When installed and in a closed position (as shownin FIG. 3), the sections 1016 and 1017 connect together via a latch 1002and a conductor cable runs through an opening 1020 formed by couplingthe sections 1016 and 1017.

The main unit 1001 comprises a sensing unit housing section 1018 thathouses a current detection device (not shown) for sensing currentflowing through the conductor cable around which the sections 1016 and1017 are installed. As described hereinabove with respect to thesatellite unit 1021, the current detection device comprises animplementation of one or more Ragowski coils as described in U.S. Pat.No. 7,940,039, which is incorporated herein by reference.

Unlike the satellite unit 1021, the main unit section 1017 comprises anextended boxlike housing section 1012. Within the housing section 1012resides one or more printed circuit boards (PCB) (not shown),semiconductor chips (not shown), and/or other electronics (not shown)for performing operations related to the general purpose transformermonitoring device 1000. In one embodiment, the housing section 1012 is asubstantially rectangular housing; however, differently sized anddifferently shaped housings may be used in other embodiments.

Additionally, the main unit 1001 further comprises one or more cables1004, 1007. The cables 1004, 1007 may be coupled to a conductor cable orcorresponding bus bars (not shown) and ground or reference voltageconductor (not shown), respectively, for the corresponding conductorcable, which will be described further herein.

Note that methods in accordance with an embodiment of the presentdisclosure use the described monitoring device 1000 for collectingcurrent and/or voltage data. Further note that the monitoring device1000 described is portable and easily connected and/or coupled to anelectrical conductor and/or transformer posts. Due to the noninvasivemethod of installing the satellite unit and main unit around a conductorand connecting the leads 1004, 1007 to connection points, an operator(or utility personnel) need not de-energize a transformer 104, 121 forconnection or coupling thereto. Further, no piercing (or other invasivetechnique) of the electrical line is needed during deployment to thepower grid. Thus, the monitoring device 1000 is easy to install. Thus,deployment to the power grid is easy to effectuate.

During operation, the satellite unit 1021 and/or the main unit 1001collects data indicative of current through a conductor cable. Thesatellite unit 1021 transmits its collected data via the cable 1011 tothe main unit 1001. Additionally, the cables 1004, 1007 may be used tocollect data indicative of voltage corresponding to a conductor cableabout which the satellite unit is installed. The data indicative of thecurrent and voltage sensed corresponding to the conductor may be used tocalculate power usage.

As indicated hereinabove, there are a number of different methods thatmay be employed using the general purpose monitoring device 1000 inorder to collect current and/or voltage data and calculate power usage.

In one embodiment, the general purpose transformer monitoring device1000 may be used to collect voltage and current data from a three phasesystem (if multiple general purpose transformer monitoring devices 100are used) or a single phase system.

With respect to a single phase system, the single phase system has twoconductor cables and a neutral cable. For example, electricity suppliedto a typical home in the United States has two conductor cables (or hotcables) and a neutral cable. Note that the voltage across the conductorcables in such an example is 240 Volts (the total voltage supplied) andthe voltage across one of the conductor cables and the neutral is 120Volts. Such an example is typically viewed as a single phase system.

In a three phase system, there are typically three conductor cables anda neutral cable (sometimes there may not be a neutral cable). In onesystem, voltage measured in each conductor cable is 120° out of phasefrom the voltage in the other two conductor cables. Multiple generalpurpose transformer monitoring devices 1000 can obtain current readingsfrom each conductor cable and voltage readings between each of theconductor cables and the neutral (or obtain voltage readings betweeneach of the conductor cables). Such readings may then be used tocalculate power usage.

Note that the main unit 1001 of the general purpose transformermonitoring device 1000 further comprises one or more light emittingdiodes (LEDs) 1003. The LEDs may be used by logic (not shown butreferred to herein with reference to FIG. 4 as analytic logic 308) toindicate status, operations, or other functions performed by the generalpurpose transformer monitoring device 1000.

FIG. 4 depicts an exemplary embodiment of the operations computingdevice 287 depicted in FIG. 2A. As shown by FIG. 4, the operationscomputing device 287 comprises analytic logic 308, meter data 390,transformer data 391, line data 392, and configuration data 312 allstored in memory 300.

The analytics logic 308 generally controls the functionality of theoperations computing device 287, as will be described in more detailhereafter. It should be noted that the analytics logic 308 can beimplemented in software, hardware, firmware or any combination thereof.In an exemplary embodiment illustrated in FIG. 4, the analytics logic308 is implemented in software and stored in memory 300.

Note that the analytics logic 308, when implemented in software, can bestored and transported on any computer-readable medium for use by or inconnection with an instruction execution apparatus that can fetch andexecute instructions. In the context of this document, a“computer-readable medium” can be any means that can contain or store acomputer program for use by or in connection with an instructionexecution apparatus.

The exemplary embodiment of the operations computing device 287 depictedby FIG. 4 comprises at least one conventional processing element 302,such as a digital signal processor (DSP) or a central processing unit(CPU), that communicates to and drives the other elements within theoperations computing device 287 via a local interface 301, which caninclude at least one bus. Further, the processing element 302 isconfigured to execute instructions of software, such as the analyticslogic 308.

An input interface 303, for example, a keyboard, keypad, or mouse, canbe used to input data from a user of the operations computing device287, and an output interface 304, for example, a printer or displayscreen (e.g., a liquid crystal display (LCD)), can be used to outputdata to the user. In addition, a network interface 305, such as a modem,enables the operations computing device 287 to communicate via thenetwork 280 (FIG. 2A) to other devices in communication with the network280.

As indicated hereinabove, the meter data 390, the transformer data 391,the line data 392, and the configuration data 312 are stored in memory300. The meter data 390 is data indicative of power usage measurementsand/or other electrical characteristics obtained from each of the meters112-117 (FIG. 1). In this regard, the meter data 390 is an aggregaterepresentation of the meter data 935-940 (FIG. 2A) received from themeter data collection devices 986-991 (FIG. 2A).

In one embodiment, the analytics logic 308 receives the meter data935-940 and stores the meter data 935-940 (as meter data 390) such thatthe meter data 935-940 may be retrieved based upon the transformer 104or 121 (FIG. 1) to which the meter data's corresponding meter 112-117 iscoupled. Note that meter data 390 is dynamic and is collectedperiodically by the meter data collection devices 986-991 from themeters 112-117. For example, the meter data 390 may include, but is notlimited to, data indicative of current measurements, voltagemeasurements, and/or power calculations over a period of time per meter112-117 and/or per transformer 104 or 121. The analytic logic 308 mayuse the collected meter data 390 to determine whether the amount ofelectricity supplied by the corresponding transformer 104 or 121 issubstantially equal to the electricity that is received at the consumerpremises 106-111.

In one embodiment, each entry of the meter data 935-940 in the meterdata 390 is associated with an identifier (not shown) identifying themeter 112-117 (FIG. 1) from which the meter data 935-940 is collected.Such identifier may be randomly generated at the meter 112-117 via logic(not shown) executed on the meter 112-117.

In such a scenario, data indicative of the identifier generated by thelogic at the meter 112-117 may be communicated, or otherwisetransmitted, to the transformer monitoring device 243 or 244 to whichthe meter is coupled. Thus, when the transformer monitoring devices 243,244 transmit transformer data 240, 241, each transformer monitoringdevice 243, 244 can also transmit its unique meter identifier (and/orthe unique identifier of the meter that sent the transformer monitoringdevice 243, 244 the meter data). Upon receipt, the analytics logic 308may store the received transformer data 240, 241 (as transformer data391) and the unique identifier of the transformer monitoring device 243,244 and/or the meter unique identifier such that the transformer data391 may be searched on the unique identifiers when performingcalculations. In addition, the analytics logic 308 may store the uniqueidentifiers of the transformer monitoring devices 243, 244 correspondingto the unique identifiers of the meters 112-117 from which thecorresponding transformer monitoring devices 243, 244 receive meterdata. Thus, the analytics logic 308 can use the configuration data 312when performing operations, such as aggregating particular meter dataentries in meter data 390 to compare to transformer data 391.

The transformer data 391 is data indicative of aggregated power usagemeasurements obtained from the distribution transformers 104, 121. Suchdata is dynamic and is collected periodically. Note that the transformerdata 240, 241 comprises data indicative of current measurements, voltagemeasurements, and/or power calculations over a period of time thatindicates the amount of aggregate power provided to the consumerpremises 106-111. Notably, the transformer data 391 comprises dataindicative of the aggregate power that is being sent to a “group,” i.e.,two or more consumer premises being monitored by the transformermonitoring devices 243, 244, although the transformer data 391 cancomprise power data that is being sent to only one consumer premisesbeing monitored by the transformer monitoring device.

In one embodiment, during setup of a distribution network 119 (FIG. 1),the analytic logic 308 may receive data identifying the uniqueidentifier for one or more transformers 104, 121. In addition, when atransformer monitoring device 243, 244 is installed and electricallycoupled to one or more transformers 104, 121, data indicative of theunique identifier of the transformers 104, 121 may be provided to themeters 112-117 and/or to the operations computing device 287, asdescribed hereinabove. The operations computing device 287 may store theunique identifiers (i.e., the unique identifier for the transformers) inconfiguration data 312 such that each meter 112-117 is correlated inmemory with a unique identifier identifying the distribution transformerfrom which the consumer premises 106-111 associated with the meter112-117 receives power.

The line data 273-275 is data indicative of power usage measurementsobtained from the line data collection system 290 along transmissionlines 101 b-101 d in the system 100. Such data is dynamic and iscollected periodically. Note that the line data 273-274 comprises dataindicative of current measurements, voltage measurements, and/or powercalculations over a period of time that indicates the amount ofaggregate power provided to the distribution substation transformer 103and the distribution transformers 104, 121. Notably, the line data 392comprises data indicative of the aggregate power that is being sent to a“group,” i.e., one or more distribution substation transformers 103.

During operation, the analytic logic 308 receives meter data 935-940 viathe network interface 305 from the network 280 (FIG. 2) and stores themeter data 935-940 as meter data 390 in memory 300. The meter data 390is stored such that it may be retrieved corresponding to thedistribution transformer 104, 121 supplying the consumer premise 106-111to which the meter data corresponds. Note there are various methods thatmay be employed for storing such data including using uniqueidentifiers, as described hereinabove, or configuration data 312, alsodescribed hereinabove.

The analytic logic 308 may perform a variety of functions to furtheranalyze the power transmission and distribution system 100 (FIG. 1). Asan example, and as discussed hereinabove, the analytic logic 308 may usethe collected transformer data 391, line data 392, and/or meter data 390to determine whether electricity theft is occurring along thetransmission lines 101 a, 101 b or the distribution lines 101 c-101 j.In this regard, the analytic logic 308 may compare the aggregate powerconsumed by the group of consumer premises (e.g., consumer premises106-108 or 109-111) and compare the calculated aggregate with the actualpower supplied by the corresponding distribution transformer 104 or 121.In addition, the analytic logic 308 may compare the power transmitted tothe distribution substation transformer 103 and the aggregate powerreceived by the distribution transformers 104, 121, or the analyticlogic 308 may compare the power transmitted to the transmissionsubstation 102 and the aggregate power received by one or moredistribution substation transformers 103.

If comparisons indicate that electricity theft is occurring anywhere inthe power and distribution system 100, the analytics logic 308 maynotify a user of the operations computing device 287 that there may be aproblem. In addition, the analytics logic 308 can pinpoint a location inthe power transmission and distribution system 100 where theft may beoccurring. In this regard, the analytic logic 308 may have a visual oraudible alert to the user, which can include a map of the system 100 anda visual identifier locating the problem.

As indicated hereinabove, the analytics logic 308 may perform a varietyof operations and analysis based upon the data received. As an example,the analytic logic 308 may perform a system capacity contributionanalysis. In this regard, the analytic logic 308 may determine when oneor more of the consumer premises 106-111 have coincident peak powerusage (and/or requirements). The analytics logic 308 determines, basedupon this data, priorities associated with the plurality of consumerpremises 106-111, e.g. what consumer premises requires a particular peakload and at what time. Loads required by the consumer premises 106-111may necessarily affect system capacity charges; thus, the priority maybe used to determine which consumer premises 106-111 may benefit fromdemand management.

Additionally, the analytic logic 308 may use the meter data 390 (FIG.4), the transformer data 391, the line data 392, and the configurationdata 312 (collectively referred to as “operations computing devicedata”) to determine asset loading. For example, analyses may beperformed for substation and feeder loading, transformer loading, feedersection loading, line section loading, and cable loading. Also, theoperations computing device data may be used to produce detailed voltagecalculations and analysis of the system 100 and/or technical losscalculations for the components of the system 100, and to comparevoltages experienced at each distribution transformer with thedistribution transformer manufacturer minimum/maximum voltage ratingsand identify such distribution transformer(s) which are operatingoutside of the manufacturer's suggested voltages range thereby helpingto isolate power sag and power swell instances, and identifydistribution transformer sizing and longevity information.

In one embodiment, a utility company may install load control devices(not shown). In such an embodiment, the analytics logic 308 may use theoperations computing device data to identify one or more locations ofload control devices.

FIG. 5 depicts an exemplary embodiment of the transformer monitoringdevice 1000 depicted in FIG. 3. As shown by FIG. 5, the transformermonitoring device 1000 comprises control logic 2003, voltage data 2001,current data 2002, and power data 2020 stored in memory 2000.

The control logic 2003 controls the functionality of the operationstransformer monitoring device 1000, as will be described in more detailhereafter. It should be noted that the control logic 2003 can beimplemented in software, hardware, firmware or any combination thereof.In an exemplary embodiment illustrated in FIG. 5, the control logic 2003is implemented in software and stored in memory 2000.

Note that the control logic 2003, when implemented in software, can bestored and transported on any computer-readable medium for use by or inconnection with an instruction execution apparatus that can fetch andexecute instructions. In the context of this document, a“computer-readable medium” can be any means that can contain or store acomputer program for use by or in connection with an instructionexecution apparatus.

The exemplary embodiment of the transformer monitoring device 1000depicted by FIG. 5 comprises at least one conventional processingelement 2004, such as a digital signal processor (DSP) or a centralprocessing unit (CPU), that communicates to and drives the otherelements within the transformer monitoring device 1000 via a localinterface 2005, which can include at least one bus. Further, theprocessing element 2004 is configured to execute instructions ofsoftware, such as the control logic 2003.

An input interface 2006, for example, a keyboard, keypad, or mouse, canbe used to input data from a user of the transformer monitoring device1000, and an output interface 2007, for example, a printer or displayscreen (e.g., a liquid crystal display (LCD)), can be used to outputdata to the user. In addition, a network interface 2008, such as a modemor wireless transceiver, enables the transformer monitoring device 1000to communicate with the network 280 (FIG. 2A).

In one embodiment, the transformer monitoring device 1000 furthercomprises a communication interface 2050. The communication interface2050 is any type of interface that when accessed enables power data2020, voltage data 2001, current data 2002, or any other data collectedor calculated by the transformer monitoring device 100 to becommunicated to another system or device. As an example, thecommunication interface may be a serial bus interface that enables adevice that communicates serially to retrieve the identified data fromthe transformer monitoring device 1000. As another example, thecommunication interface 2050 may be a universal serial bus (USB) thatenables a device configured for USB communication to retrieve theidentified data from the transformer monitoring device 1000. Othercommunication interfaces 2050 may use other methods and/or devices forcommunication including radio frequency (RF) communication, cellularcommunication, power line communication, and WiFi communications. Thetransformer monitoring device 1000 further comprises one or more voltagedata collection devices 2009 and one or more current data collectiondevices 2010. In this regard, with respect to the transformer monitoringdevice 1000 depicted in FIG. 3, the transformer monitoring device 1000comprises the voltage data collection device 2009 that may include thecables 1004, 1007 (FIG. 3) that sense voltages at nodes (not shown) on atransformer to which the cables are attached. As will be describedfurther herein, the control logic 2003 receives data via the cables1004, 1007 indicative of the voltages at the nodes and stores the dataas voltage data 2001. The control logic 2003 performs operations on andwith the voltage data 2001, including periodically transmitting thevoltage data 2001 to, for example, the operations computing device 287(FIG. 2A).

Further, with respect to the transformer monitoring device 1000 depictedin FIG. 3, the transformer monitoring device 1000 comprises the currentsensors (not shown) contained in the sensing unit housing 1005 (FIG. 3)and the sensing unit housing section 1018 (FIG. 3), which are describedhereinabove. The current sensors sense current traveling throughconductor cables (or neutral cables) around which the sensing unithousings 1005, 1018 are coupled. As will be described further herein,the control logic 2003 receives data indicative of current from thesatellite sensing unit 1021 (FIG. 3) via the cable 1011 and dataindicative of the current from the current sensor of the main unit 1001contained in the sensing unit housing section 1018. The control logic2003 stores the data indicative of the currents sensed as the currentdata 2002. The control logic 2003 performs operations on and with thecurrent data 2002, including periodically transmitting the voltage data2001 to, for example, the operations computing device 287 (FIG. 2A).

Note that the control logic 2003 may perform calculations with thevoltage data 2001 and the current data 2002 prior to transmitting thevoltage data 2001 and the current data 2002 to the operations computingdevice 287. In this regard, for example, the control logic 2003 maycalculate power usage using the voltage data 2001 and current data 2002over time and periodically store resulting values as power data 2020.

During operations, the control logic 2003 may transmit data to theoperations computing device 287 via the cables via a power linecommunication (PLC) method. In other embodiments, the control logic 2003may transmit the data via the network 280 (FIG. 2A) wirelessly orotherwise.

FIGS. 6-10 depict one exemplary practical application, use, andoperation of the transformer monitoring device 1000 shown in the drawingin FIG. 3. In this regard, FIG. 6 is a transformer can 1022, whichhouses a transformer (not shown), mounted on a utility pole 1036. One ormore cables 1024-1026 carry current from the transformer can 1022 to adestination (not shown), e.g., consumer premises 106-111 (FIG. 1). Thecables 1024-1026 are connected to the transformer can at nodes1064-1066. Each node 1064-1066 comprises a conductive connector (part ofwhich is sometimes referred to as a bus bar).

FIG. 7 depicts the satellite unit 1021 of the transformer monitoringdevice 1000 being placed on one of the nodes 1064-1066 (FIG. 6), i.e.,in an open position. A technician (not shown), e.g., an employee of autility company (not shown), decouples the latch 1006 (FIG. 3), made upby decoupled sections 1006 a and 1006 b, and places the sections 1088and 1089 around a portion of the node 1064-1066 such that the sensorunit (not shown) interfaces with the node and senses a current flowingthrough the node. FIG. 8 depicts the satellite unit 1021 of thetransformer monitoring device 1000 latched around the node 1064-1066 ina closed position.

FIG. 9 depicts the main unit 1001 of the transformer monitoring device1000 being placed on one of the nodes 1064-1066, i.e., in an openposition. The technician decouples the latch 1002, made up by decoupledsections 1002 a and 1002 b, and places the sections 1016 and 1017 arounda portion of the node 1064-1066 such that the sensor unit (not shown)interfaces with the node and senses a current flowing through the node.FIG. 10 is a drawing of the transformer monitoring device 1000 latchedaround the node 1064-1066. FIG. 10 depicts the main unit 1001 of thetransformer monitoring device 1000 latched around the node 1064-1066 andin a closed position.

In one embodiment, the cables 1004, 1007 (FIG. 3) of the main unit 1001may be connected to one of the nodes 1064-1066 about which therespective satellite unit 1021 is coupled and one of the nodes 1064-1066about which the main unit 1001 is coupled. In this regard, as describedhereinabove, the cable 1004 comprises a plurality of separate anddistinct cables. One cable is connected to the node about which thesatellite unit 1021 is coupled, and one cable is connected to the nodeabout which the main unit 1001 is coupled.

During operation, the current detection device contained in the sensingunit housings 1005, 1018 (FIG. 3) sense current from the respectivenodes to which they are coupled. Further, the connections made by thecables 1004, 1007 to the nodes and reference conductor sense the voltageat the respective nodes, i.e., the node around which the main unit iscoupled and the node around which the satellite unit is coupled.

In one embodiment, the analytic logic 308 receives current data for eachnode and voltage data from each node based upon the current sensors andthe voltage connections. The analytics logic 308 uses the collected datato calculate power over a period of time, which the analytic logic 308transmits to the operations computing device 287 (FIG. 2A). In anotherembodiment, the analytic logic 308 may transmit the voltage data and thecurrent data directly to the operations computing device 287 withoutperforming any calculations.

FIGS. 11-13 further illustrate methods that may be employed using themonitoring device 1000 FIG. 3 in a system 100 (FIG. 1). As describedhereinabove, the monitoring device 1000 may be coupled to a conductorcable (not shown) or a bushing (not shown) that attaches the conductorcable to a transformer can 1022 (FIG. 6). In operation, the transformermonitoring device 1000 obtains a current and voltage reading associatedwith the conductor cable to which it is coupled, as describedhereinabove, and the main unit 1001 (FIG. 3) uses the current readingand the voltage reading to calculate power usage.

Note for purposes of the discussion hereinafter, a transformermonitoring device 1000 (FIG. 3) comprises two current sensing devices,including one contained in housing 1005 (FIG. 3) and one contained inthe housing 1018 (FIG. 3) of the satellite unit 1021 (FIG. 3) and themain unit 1001 (FIG. 3), respectively.

FIG. 11 is a diagram depicting a distribution transformer 1200 fordistributing three-phase power, which is indicative of a “wye”configuration. In this regard, three-phase power comprises threeconductors providing AC power such that the AC voltage waveform on eachconductor is 120° apart relative to each other, where 360° isapproximately one sixtieth of a second. As described hereinabove,three-phase power is transmitted on three conductor cables and isdelivered to distribution substation transformer 103 (FIG. 1) anddistribution transformer 104 (FIG. 1) on three conductor cables. Thus,the receiving distribution transformer 104 has three winding pairs (onefor each phase input voltage received) to transform the voltage of thepower received to a level of voltage needed for delivery to theconsumers 106-108 (FIG. 1).

In the distribution transformer 1200, three single-phase transformers1201-1203 are connected to a common (neutral) lead 1204. For purposes ofillustration, each transformer connection is identified as a phase,e.g., Phase A/transformer 1201, Phase B/transformer 1202, and PhaseC/transformer 1203.

In the embodiment depicted in FIG. 11, three monitoring devices 1000 a,1000 b, and 1000 c (each configured substantially similar to monitoringdevice 1000 (FIG. 3)) are employed to obtain data (e.g., voltage andcurrent data) used to calculate the power at the distributiontransformer 1200.

In this regard, at least one of current sensing devices 1217 ofmonitoring device 1000 a is used to collect current data for Phase A.Notably, the sensing device 1217 of the monitoring device 1000 a used tocollect current data may be housed in the satellite unit 1021 (FIG. 3)or the main unit 1001 (FIG. 3). The voltage lead 1004 a of themonitoring device 1000 a is connected across the Phase A conductor cableand common 1204 in order to obtain voltage data. Note that in oneembodiment both current sensing devices in the satellite unit 1021 andthe main unit 1001 (current sensing device 1217) may be coupled aroundthe Phase A conductor cable.

Further, a current sensing device 1218 of monitoring device 1000 b isused to collect current data for Phase B. As described above withreference to Phase A, the sensing device 1218 of the monitoring device1000 b used to collect current data may be housed in the satellite unit1021 (FIG. 3) or the main unit 1001 (FIG. 3). The voltage lead 1004 b ofthe monitoring device 1000 b is connected across the Phase B conductorcable and common 1204 in order to obtain voltage data. Similar to thePhase A implementation described above, in one embodiment both currentsensing device in the satellite unit 1021 and the main unit 1001(current sensing device 1218) may be coupled around the Phase Bconductor cable.

Additionally, a current sensing device 1219 of monitoring device 1000 cis used to collect voltage and current data for Phase C. As describedabove with reference to Phase A, the sensing device 1219 of themonitoring device 1000 c that is used to collect current data may behoused in the satellite unit 1021 (FIG. 3) or the main unit 1001 (FIG.3). The voltage lead 1004 c of the monitoring device 1000 c is connectedacross the Phase C conductor cable and common 1204 in order to obtainvoltage data. Similar to the Phase A implementation described above, inone embodiment both current sensing devices in the satellite unit 1021and the main unit 1001 (current sensing device 1219) may be coupledaround the Phase C conductor cable.

During monitoring, control logic 2003 (FIG. 5) of the monitoring devices1000 a-1000 c use current measurements and voltage measurements tocalculate total power. As described hereinabove, the power calculatedfrom the measurements made by the transformer monitoring devices 1000 a,1000 b, and 1000 c may be used in various applications to provideinformation related to the power transmission and distribution system100 (FIG. 1).

FIG. 12 is a diagram depicting a distribution transformer 1300 fordistributing three-phase power, which is indicative of a deltaconfiguration. Such distribution transformer 1300 may be used as thedistribution transformer 104 (FIG. 1). The distribution transformer 1300(similar to the distribution transformer 1200 (FIG. 11)) has threesingle phase transformers to transform the voltage of the power receivedon three conductor cables (i.e., three-phase power) to a level ofvoltage needed for delivery to the consumers 106-108 (FIG. 1).

The distribution transformer 1300 comprises three single-phasetransformers 1301-1303. For purposes of illustration, each transformerconnection is identified as a phase, e.g., Phase A/transformer1301-transformer 1303, Phase B/transformer 1302-transformer 1301, andPhase C/transformer 1303-transformer 1302.

In the embodiment depicted in FIG. 12, two transformer monitoringdevices 1000 d and 1000 e are employed to obtain voltage and currentdata, which are used to calculate power at the distribution transformer1300. In this regard, transformer monitoring device 1000 d is coupledabout one of three incoming conductor cables, identified in FIG. 12 asPhase B, and transformer monitoring device 1000 e is coupled aboutanother one of the three incoming conductor cables, identified in FIG.12 as Phase C. The monitoring devices 1000 d and 1000 e (each configuredsubstantially similar to monitoring device 1000 (FIG. 3)) are employedto obtain data (e.g., voltage and current data) used to calculate thepower at the distribution transformer 1300.

In this regard, a current sensing device 1318 of monitoring device 1000d is used to collect current data for Phase B. Notably, the sensingdevice 1318 of the monitoring device 1000 d used to collect current datamay be housed in the satellite unit 1021 (FIG. 3) or the main unit 1001(FIG. 3). The voltage leads 1004 d of the monitoring device 1000 d areconnected across the Phase B conductor cable and the Phase A conductorcable which measures a voltage differential. Note that in one embodimentboth current sensing devices in the satellite unit 1021 and the mainunit 1001 (current sensing device 1318) may be coupled around the PhaseB conductor cable. Further note that in the delta configuration, Phase Amay be arbitrarily designated as a “common” such that power may becalculated based on the voltage differentials between the current-sensedconductor cables and the designated “common,” which in the presentembodiment is Phase A.

Further, similar to Phase B measurements, a current sensing device 1319of monitoring device 1000 e is used to collect current data for Phase C.As described above with reference to Phase B, the sensing device 1319 ofthe monitoring device 1000 e used to collect current data may be housedin the satellite unit 1021 (FIG. 3) or the main unit 1001 (FIG. 3). Thevoltage leads 1004 e of the monitoring device 1000 e are connectedacross the Phase C conductor cable and Phase A conductor cable. Notably,in one embodiment both current sensing devices in the satellite unit1021 and the main unit 1001 (current sensing device 1319) may be coupledaround the Phase C conductor cable.

During monitoring, control logic 2003 (FIG. 5) of the monitoring devices1000 d and 1000 e use current measurements and voltage measurements tocalculate total power. As described hereinabove, the power calculatedfrom the measurements made by the transformer monitoring devices 1000 fand 1000 g may be used in various applications to provide informationrelated to the power transmission and distribution system 100 (FIG. 1).

FIG. 13 is a diagram depicting a distribution transformer 1400 fordistributing power, which is indicative of an open delta configuration.The distribution transformer 1400 has two single phase transformers totransform the voltage received to a level of voltage needed for deliveryto the consumers 106-108 (FIG. 1).

The distribution transformer 1400 comprises two single-phasetransformers 1401-1402. In the embodiment depicted in FIG. 13, twotransformer monitoring devices 1000 f and 1000 g are employed to obtainvoltage and current data, which are used to calculate power at thedistribution transformer 1400.

Transformer monitoring device 1000 f is coupled about one of threeconductor cables identified in FIG. 13 as Phase A and transformermonitoring device 1000 g is coupled about another one of the conductorcables identified in FIG. 13 as Phase B. The monitoring devices 1000 fand 1000 g (each configured substantially similar to monitoring device1000 (FIG. 3)) are employed to obtain data (e.g., voltage and currentdata) used to calculate the power at the distribution transformer 1400.

In this regard, at least one of the current sensing devices 1418 or 1419of monitoring device 1000 f is used to collect voltage and current datafor Phase A. While both sensing devices are shown coupled about Phase A,both are not necessarily needed in other embodiments. Notably, a sensingdevice of the monitoring device 1000 f used to collect current data maybe housed in the satellite unit 1021 (FIG. 3) or the main unit 1001(FIG. 3). The voltage leads 1004 f of the monitoring device 1000 f areconnected across the Phase A conductor cable and ground. Note that inone embodiment both current sensing devices in the satellite unit 1021and the main unit 1001 may be coupled around the Phase A conductorcable, as shown.

Further, current sensing device 1420 housed in the main unit 1001 (FIG.3) of monitoring device 1000 g and current sensing device 1421 housed inthe satellite unit 1021 (FIG. 3) of monitoring device 1000 g is used tocollect current data for Phase B. The voltage lead 1004 g of themonitoring device 1000 g is connected across the voltage outputs of thesecondary of transformer 1402.

During monitoring, control logic 2003 (FIG. 5) of the transformermonitoring devices 1000 f and 1000 g uses current measurements andvoltage measurements to calculate total power. As described hereinabove,the power calculated from the measurements made by the transformermonitoring devices 1000 f and 1000 g may be used in various applicationsto provide information related to the power transmission anddistribution system 100 (FIG. 1).

FIG. 14 depicts an exemplary polyphase distribution transformer monitor(PDTM) 1499 in accordance with an embodiment of the present disclosure.For purposes of this disclosure, in one embodiment, polyphase refers toa system for distributing alternating current electrical power and hasthree or more electrical conductors wherein each carries alternatingcurrents having time offsets one from the others.

Notably, with reference to FIG. 2A, the PDTM 1499 may serve the purposeand functionality and is a type of transformer monitoring device 244,243 (FIG. 2A). Thus, the PDTM collects power and electricalcharacteristic data related to a particular distribution transformer104, 121 (FIG. 1).

The PDTM 1499 comprises a control box 1498, which is a housing thatconceals a plurality of electronic components, discussed further herein,that control the PDTM 1499. Additionally, the PDTM comprises a pluralityof satellite current sensors 1490-1493.

The satellite current sensors 1490-1493 are structurally andfunctionally substantially similar to the satellite unit 1021 describedwith reference to FIGS. 3, 7, and 8. In this regard, the satellitecurrent sensors 1490-1493 detect a current through an electrical cable,bus bar, or any other type of node through which current passes intoand/or from a distribution transformer, such as the distributiontransformer shown in FIG. 6.

Further, the satellite current sensors 1490-1493 are electricallyconnected to the control box 1498 (and to the electronics (not shown)contained therein). In this regard, the satellite current sensor 1490 iselectrically connected via connectors 1464, 1460 on the satellitecurrent sensor 1490 and the control box 1498, respectively, by a voltagecurrent cable 1480. Similarly, the satellite current sensor 1491 iselectrically connected via connectors 1465, 1461 on the satellitecurrent sensor 1491 and the control box 1498, respectively, by a voltagecurrent cable 1481, the satellite current sensor 1492 is electricallyconnected via connectors 1466, 1462 on the satellite current sensor 1492and the control box 1498, respectively, by a voltage current cable 1482,and the satellite current sensor 1493 is electrically connected viaconnectors 1467, 1463 on the satellite current sensor 1493 and thecontrol box 1498, respectively, by a voltage current cable 1483.

Note that the current cables 1480-1483 may be an American NationalStandards Institute (ANSI)-type cable. In this regard, the currentcables 1480-1483 may be either insulated or non-insulated. The currentcables 1480-1483 may be any other type of cable known in the art orfuture-developed from transferring data indicative of currentmeasurements made by the satellite current sensors 1490-1493 to thecontrol box 1498.

Additionally, each satellite current sensor 1490-1493.

In addition, each current cable 1480-1483 is further associated andelectrically correlated with a voltage cable 1484-1487. In this regard,each voltage cable 1484 extends from the connectors 1460-1463 on thecontrol box 1498 and terminates with ring terminals 1476-1479,respectively.

During operation, one or more of the satellite current sensors 1490-1493are installed about conductors (e.g., cables), bus bars, or other typeof node through which current travels. In addition, each of the ringterminals 1476-1479, respectively, are coupled to the conductor, busbar, or other type of node around which their respective satellitecurrent sensor 1490-1493 is installed.

More specifically, each satellite current sensor 1490-1493 takes currentmeasurements over time of current that is flowing through the conductorcable, bus bar, or node around which it is installed. Also, over time,voltage measurements are sensed via each of the satellite currentsensors' respective voltage cables 1484-1487. As will be describedherein, the current measurements and voltage measurements taken overtime are correlated and thus used in order to determine power usagecorresponding to the particular conductor cable, bus bar, or particularnode.

FIG. 15 depicts an exemplary embodiment of a controller 1500 that ishoused within the control box 1498. As shown by FIG. 15, the controller1500 comprises control logic 1503, voltage data 1501, current data 1502,and power data 1520 stored in memory 1522.

The control logic 1503 controls the functionality of the controller1500, as will be described in more detail hereafter. It should be notedthat the control logic 1503 can be implemented in software, hardware,firmware or any combination thereof. In an exemplary embodimentillustrated in FIG. 15, the control logic 1503 is implemented insoftware and stored in memory 1522.

Note that the control logic 1503, when implemented in software, can bestored and transported on any computer-readable medium for use by or inconnection with an instruction execution apparatus that can fetch andexecute instructions. In the context of this document, a“computer-readable medium” can be any means that can contain or store acomputer program for use by or in connection with an instructionexecution apparatus.

The exemplary embodiment of the controller 1500 depicted by FIG. 15comprises at least one conventional processing element 1504, such as adigital signal processor (DSP) or a central processing unit (CPU), thatcommunicates to and drives the other elements within the controller 1500via a local interface 1505, which can include at least one bus. Further,the processing element 1504 is configured to execute instructions ofsoftware, such as the control logic 1503.

In addition, a network interface 1561, such as a modem or wirelesstransceiver, enables the controller 1500 to communicate with the network280 (FIG. 2A).

In one embodiment, the controller 1500 further comprises a communicationinterface 1560. The communication interface 1560 is any type ofinterface that when accessed enables power data 1520, voltage data 1501,current data 1502, or any other data collected or calculated by thecontroller 1500 to be communicated to another system or device.

As an example, the communication interface 1560 may be a serial businterface that enables a device that communicates serially to retrievethe identified data from the controller 1500. As another example, thecommunication interface 1560 may be a universal serial bus (USB) thatenables a device configured for USB communication to retrieve theidentified data from the controller 1500. Other communication interfacesmay use other methods and/or devices for communication including radiofrequency (RF) communication, cellular communication, power linecommunication, and Wi-Fi communications.

The controller 1500 further comprises one or more current cableinterfaces 1550-1553 and voltage cable interfaces 1554-1557 that receivedata transmitted via the current cables 1480-1483 and voltage cables1484-1487, respectively. In this regard, each current cableinterface/voltage cable interface pair is associated with a singleconnector. For example, connector 1460 receives cables 1480 (current)and 1484 (voltage), and the current cable interface 1550 receives dataindicative of current and the voltage cable interface 1554 receives dataindicative of current associated with the conductor about which thesatellite current sensor 1490 is installed.

Similarly, connector 1461 receives cables 1481(current) and1485(voltage), and the current cable interface 1551 receives dataindicative of current and the voltage cable interface 1555 receives dataindicative of current associated with the conductor about which thesatellite current sensor 1491 is installed. The connector 1462 receivescables 1482(current) and 1486(voltage), and the current cable interface1552 receives data indicative of current and the voltage cable interface1556 receives data indicative of current associated with the conductorabout which the satellite current sensor 1492 is installed. Finally,connector 1463 receives cables 1483(current) and 1487(voltage), and thecurrent cable interface 1553 receives data indicative of current and thevoltage cable interface 1557 receives data indicative of currentassociated with the conductor about which the satellite current sensor1493 is installed.

During operation, the control logic 1503 receives the voltage andcurrent data from the interfaces 1550-1557 and stores the current dataas current data 1502 and the voltage data as voltage data 1501. Thecontrol logic 1503 performs operations on and with the voltage data 1501and current data 1502, including periodically transmitting the voltagedata 1501 and current data 1502 to, for example, the operationscomputing device 287 (FIG. 2A).

Note that the control logic 1503 may perform calculations with thevoltage data 1501 and the current data 1502 prior to transmitting thevoltage data 1501 and the current data 1502 to the operations computingdevice 287. In this regard, for example, the control logic 2003 maycalculate power usage using the voltage data 1501 and current data 1502over time and periodically store resulting values as power data 1520.

During operations, the control logic 1503 may transmit data to theoperations computing device 287 via the cables via a power linecommunication (PLC) method. In other embodiments, the control logic 1503may transmit the data via the network 280 (FIG. 2A) wirelessly orotherwise.

FIGS. 16-18 depict exemplary installations on differing types ofelectrical service connections for three-phase electric powerinstallations. In this regard, FIG. 16 depicts a four-wire grounded“Wye” installation 1600, FIG. 17 depicts a three-wire Delta installation1700, and FIG. 18 depicts a four-wire tapped Delta neutral groundedinstallation 1800. Each of these is discussed separately in the contactof installing and operating a PDTM 1499 for the collection of voltageand current data for the calculation of power usage date on thesecondary windings (shown per FIGS. 16-18) for each type ofinstallation.

In particular, FIG. 16 is a diagram depicting a Wye installation 1600(also referred to as a “star” three-phase configuration. While the Wyeinstallation can be a three-wire configuration, the installation 1600 isimplemented as a four-wire configuration. The installation comprises thesecondary windings of a transformer, which are designated generally as1601. The installation comprises four conductors, including conductorsA, B, C, and N (or neutral), where N is connected to ground 1602. In theinstallation 1600, the magnitudes of the voltages between each phaseconductor (e.g., A, B, and C) are equal. However, the Wye configurationthat includes a neutral also provides a second voltage magnitude, whichis between each phase and neutral, e.g., 208/120V systems.

During operation, the PDTM 1499 (FIG. 14) is connected to theinstallation 1600 as indicated. In this regard, satellite current sensor1490 is coupled about conductor A, and its corresponding voltage ringterminal 1476 is electrically coupled to conductor A. Thus, the controllogic 1503 receives data indicative of voltage and current measured fromconductor A and stores the corresponding data as voltage data 1501 andcurrent data 1502. Similarly, satellite current sensor 1491 is coupledabout conductor B, and its corresponding voltage ring terminal 1477 iselectrically coupled to conductor B, satellite current sensor 1492 iscoupled about N (neutral), and its corresponding voltage ring terminal1478 is electrically coupled to N, and, satellite current sensor 1493 iscoupled about conductor C, and its corresponding voltage ring terminal1479 is electrically coupled to conductor C. Thus, over time the controllogic 1503 receives and collects data indicative of voltage and currentmeasured from each conductor and neutral and stores the correspondingdata as voltage data 1501 and current data 1502. The control logic 1503may then use the collected data to calculate power usage over the periodof time for which voltage and current data is received and collected.

Further, FIG. 17 is a diagram depicting a Delta installation 1700. TheDelta installation 1700 shown is a three-wire configuration. Theconnections made in the Delta configuration are across each of the threephases, or the three secondary windings of the transformer. Theinstallation comprises the secondary windings of a transformer, whichare designated generally as 1701. The installation comprises threeconductors (i.e., three-wire), including conductors A, B, and C. In theinstallation 1700, the magnitudes of the voltages between each phaseconductor (e.g., A, B, and C) are equal.

During operation, the PDTM 1499 (FIG. 14) is connected to theinstallation 1700 as indicated. In this regard, satellite current sensor1490 is coupled about conductor A, and its corresponding voltage ringterminal 1476 is electrically coupled to conductor A. Thus, the controllogic 1503 receives data indicative of voltage and current measured fromconductor A and stores the corresponding data as voltage data 1501 andcurrent data 1502. Similarly, satellite current sensor 1491 is coupledabout conductor B, and its corresponding voltage ring terminal 1477 iselectrically coupled to conductor B, and satellite current sensor 1492is coupled about C, and its corresponding voltage ring terminal 1478 iselectrically coupled to C. In regards to the fourth satellite currentsensor 1492, because the installation 1700 is a three-wire set up, thefourth satellite current sensor 1493 is not needed, and may thereforenot be coupled to a conductor. Similar to the installation 1600, overtime the control logic 1503 receives and collects data indicative ofvoltage and current measured from each conductor (A, B, and C) andstores the corresponding data as voltage data 1501 and current data1502. The control logic 1503 may then use the collected data tocalculate power usage over the period of time for which voltage andcurrent data is received and collected.

FIG. 18 is a diagram depicting a Delta installation 1800 in which onewinding is center-tapped to ground 1802, which is often times referredto as a “high-leg Delta configuration.” The Delta installation 1800shown is a four-wire configuration. The connections made in the Deltainstallation 1800 are across each of the three phases and neutral (orground), or the three secondary windings of the transformer and ground.The installation 1800 comprises the secondary windings of a transformer,which are designated generally as 1801. The installation comprises threeconductors, including conductors A, B, and C and the center-tapped N(neural) wire. The installation 1800 is not symmetrical and producesthree available voltage.

During operation, the PDTM 1499 (FIG. 14) is connected to theinstallation 1800 as indicated. In this regard, satellite current sensor1490 is coupled about conductor A, and its corresponding voltage ringterminal 1476 is electrically coupled to conductor A. Thus, the controllogic 1503 receives data indicative of voltage and current measured fromconductor A and stores the corresponding data as voltage data 1501 andcurrent data 1502. Similarly, satellite current sensor 1491 is coupledabout conductor B, and its corresponding voltage ring terminal 1477 iselectrically coupled to conductor B, satellite current sensor 1492 iscoupled about N, and its corresponding voltage ring terminal 1478 iselectrically coupled to N, and satellite current sensor 1493 is coupledabout conductor C, and its corresponding voltage ring terminal 1479 iselectrically coupled to C. Similar to the installation 1600, over timethe control logic 1503 receives and collects data indicative of voltageand current measured from each conductor (A, B, C, and N) and stores thecorresponding data as voltage data 1501 and current data 1502. Thecontrol logic 1503 may then use the collected data to calculate powerusage over the period of time for which voltage and current data isreceived and collected.

FIG. 19 is a flowchart depicting exemplary architecture andfunctionality of the system 100 depicted in FIG. 1.

In step 1900, electrically interfacing a first transformer monitoringdevice 1000 (FIG. 3) to a first electrical conductor of a transformer ata first location on a power grid, and in step 1901 measuring a firstcurrent through the first electrical conductor and a first voltageassociated with the first electrical conductor.

In step 1902, electrically interfacing a second transformer monitoringdevice 1000 with a second electrical conductor electrically connected tothe transformer, and in step 1903 measuring a second current through thesecond electrical conductor and a second voltage associated with thesecond electrical conductor.

Finally, in step 1904, calculating values indicative of powercorresponding to the transformer based upon the first current and thefirst voltage and the second current and the second voltage.

FIG. 20 is a flowchart depicting exemplary architecture andfunctionality of the system 100 depicted in FIG. 1 in regards to thePDTM 1499 (FIG. 14).

In step 5000, electrically interfacing a first current sensing deviceand a first voltage lead to a first electrical conductor of athree-phase transformer. With reference to FIG. 17, one exemplaryinstallation includes coupling satellite current sensor 1490 toconductor A and ring terminal 1476 to the same conductor A, for example.

In step 5001 electrically interfacing a second current sensing deviceand a second voltage lead to a second electrical conductor of athree-phase transformer. With reference to FIG. 17, one exemplaryinstallation includes coupling satellite current sensor 1491 toconductor B and ring terminal 1477 to the same conductor B, for example.

In step 5002 electrically interfacing a third current sensing device anda third voltage lead to a third electrical conductor of a three-phasetransformer. With reference to FIG. 17, one exemplary installationincludes coupling satellite current sensor 1492 to conductor C and ringterminal 1478 to the same conductor C, for example.

In step 5003, receiving data indicative of current and voltagemeasurements via the sensing devices and the voltage leads by a singleprocessor. Notably, the data is collected over a period of time by theprocessor 1504 (FIG. 15) and stored in memory 1522 (FIG. 15).

Finally, in step 5004, calculating values indicative of powercorresponding to the transformer based upon the voltage and current datareceived and stored

What is claimed is:
 1. A system for monitoring power, comprising: apolyphase distribution transformer monitoring (PDTM) device configuredto interface with at least three electrical conductors electricallyconnected to a transformer, the PDTM device further configured tomeasure a current and a voltage of each of the three electricalconductors; and logic configured to calculate values indicative of powercorresponding to the transformer based upon the currents and thevoltages measured and transmit data indicative of the calculated values.2. The system for monitoring power of claim 1, wherein the PDTM devicecomprises a control box.
 3. The system for monitoring power of claim 2,wherein the PDTM device further comprises at least three current sensorselectrically coupled to the control box.
 4. The system for monitoringpower of claim 3, wherein the PDTM device further comprises voltagecables for each of the at least three current sensors.
 5. The system formonitoring power of claim 4, wherein the logic is configured to receivedata from each of the three current sensors indicative of a sensedcurrent in each of the respective conductors.
 6. The system formonitoring power of claim 5, wherein the logic is further configured toreceived data indicative of voltage of each of the conductors andcorresponding to each of the current sensors.
 7. A method for monitoringpower, comprising: interfacing a polyphase distribution transformermonitoring (PDTM) device having at least three current sensors and threevoltage leads corresponding to the current sensors with at least threeelectrical conductors electrically connected to a transformer bycoupling; measuring a current and a voltage of each of the threeelectrical conductors via the current sensors and the voltage leads;calculating values indicative of power corresponding to the transformerbased upon the current and the voltage measured; and transmitting dataindicative of the calculated values.
 8. The method for monitoring powerof claim 2, further comprising electrically coupling at least threecurrent sensors to a control box.
 9. The method for monitoring power ofclaim 4, further comprising receiving data from each of the threecurrent sensors indicative of a sensed current in each of the respectiveconductors.
 10. The method for monitoring power of claim 5, furthercomprising receiving data indicative of voltage of each of theconductors and corresponding to each of the current sensors.